Settable compositions and methods of use

ABSTRACT

Disclosed herein are settable compositions and methods of using settable compositions in a wellbore. In one embodiment a method of introducing a settable composition into a wellbore is described. The method comprises providing a settable composition comprising pumice, hydrated lime, a set retarder, and water. Introducing the settable composition into a wellbore. Allowing the settable composition to remain static in the wellbore, wherein the settable composition remains in a pumpable fluid state for a period of about 1 day or longer while static in the wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of U.S. patent applicationSer. No. 14/194,125 filed on Feb. 28, 2014 which is acontinuation-in-part of U.S. patent application Ser. No. 13/417,001,filed on Mar. 9, 2012, the entire disclosure of which is incorporatedherein by reference.

BACKGROUND

Embodiments relate to subterranean operations and, in certainembodiments, to settable compositions and methods of using settablecompositions in subterranean formations.

During the drilling of a wellbore in a subterranean formation, adrilling fluid may be used to, among other things, cool the drill bit,lubricate the rotating drill string to prevent it from sticking to thewalls of the well bore, prevent blowouts by serving as a hydrostatichead to counteract the sudden entrance into the well bore of highpressure formation fluids, and remove drill cuttings from the well bore.A drilling fluid may be circulated downwardly through a drill pipe anddrill bit and then upwardly through the wellbore to the surface. Thedrilling fluid used may be any number of fluids (gaseous or liquid) andmixtures of fluids and solids (such as solid suspensions, mixtures, andemulsions).

After drilling to a desired depth and prior to and in preparation of thecementing phase, the drill bit may be withdrawn from the wellbore, andcirculation of the drilling fluid is stopped. The drilling fluid may beleft in the wellbore along with a filter cake of solids from thedrilling fluid. Next, a pipe string (e.g., casing, liners, etc.) may beintroduced into the well bore. Depending on the depth of the well boreand whether or not any problems are encountered in introducing the pipestring into the well bore, the drilling fluid may remain relativelystatic in the well bore for a relatively long time period, for example,up to about 2 weeks or longer. While drilling fluids are generally notsettable (e.g., they generally do not to form a hardened mass overtime), drilling fluids may increase in gel strength over time.Accordingly, during the time period that the drilling fluid is static inthe well bore, portions of the drilling fluid may increase in gelstrength so that displacement of the drilling fluid from within the wellbore may be become more difficult. At a desired time, the pipe stringmay be cemented in place by pumping a cement composition through thepipe string and into the annulus between the pipe string and the wallsof the well bore whereby the drilling fluid in the annulus is displacedtherefrom by the cement composition. While a variety of techniques havebeen developed for improving the displacement of the drilling fluid fromthe annulus, if the drilling fluid has developed gel strength due toremaining static in the well bore for a long period of time, portions ofthe drilling fluid in the well bore are bypassed by the cementcomposition. Since the drilling fluid is not settable, i.e., it does notset into a rigid sealable mass, formation fluids enter and flow in thewell bore which is highly undesirable.

-   -   In some instances, a settable composition (commonly referred to        as a “settable spotting composition”) may be used to remove        drilling fluid and prevent the drilling fluid filter cake from        interfering with subsequent primary cementing operations. These        settable spotting compositions may be used to at least partially        displacing the drilling fluid before the drilling fluid in the        wellbore has had a chance to gain significant gel strength, for        example, prior to introducing the pipe string into the well        bore. Generally, these settable spotting compositions should not        have an undesirable increase in gel strength after being static        in the wellbore for a period of time, for example, up to at        least two weeks, so that the settable spotting compositions may        be displaced from the wellbore. After the wellbore is at least        partially filled with the settable spotting composition, the        pipe string to be cemented may be introduced into the wellbore.        When the cement composition is pumped through the pipe string        into the annulus, the drilling fluid (if any) and settable        spotting composition in the pipe string and annulus should be        displaced ahead of the cement composition. The settable spotting        composition, if any, remaining in fractures or other permeable        portions of the subterranean formation should set into a        hardened mass, thereby preventing or reducing the entry or flow        of formation fluids in the annulus.

In alternative operations, commonly referred to as “puddle jobs,” asettable composition may be placed into the wellbore before the casingand consequently the settable composition must remain in a fluid puddlestate long enough for the casing string to be placed into the wellbore.Once the casing string is successfully positioned the settablecomposition may then set into a hardened mass, which may be sealableand/or may prevent the migration of fluids in the wellbore.

While settable compositions have been developed heretofore, challengesexist with their successful use in subterranean cementing operations.For example, settable compositions used as settable spottingcompositions should ideally remain fluid long enough so that they canultimately be displaced with the cement composition or any associatedspacer fluids. Similarly, settable compositions used in puddle jobsshould ideally remain fluid long enough to place and position the casingwithin the wellbore. Moreover, it may be desirable for the settablecompositions to develop a sufficient compressive strength when it is nolonger desired for the settable composition to remain fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present method, and should not be used to limit or define themethod.

FIG. 1 illustrates surface equipment that may be used in the placementof a settable composition in a wellbore in accordance with certainembodiments.

FIG. 2A illustrates a method for placement of a settable compositioninto a wellbore annulus in accordance with certain embodiments.

FIG. 2B illustrates a method for the placement of a settable compositioninto a wellbore annulus in accordance with certain embodiments.

FIG. 2C illustrates a method for the placement of a settable compositioninto a wellbore annulus in accordance with certain embodiments.

FIG. 2D illustrates a method for the placement of a settable compositioninto a wellbore annulus in accordance with certain embodiments.

FIG. 3 illustrates a method for the placement of a settable compositioninto a wellbore in accordance with certain embodiments.

FIG. 4 illustrates the placement of a pipe string into a wellboreannulus at least partially filled with a settable composition inaccordance with certain embodiments.

FIG. 5A illustrates a “right-angle” set profile of a settablecomposition in accordance with certain embodiments.

FIG. 5B illustrates a gelation set profile of a settable composition inaccordance with certain embodiments.

DESCRIPTION OF PREFERRED EMBODIMENTS

Embodiments relate to subterranean operations and, in certainembodiments, to settable compositions and methods of using settablecompositions in subterranean formations.

Embodiments of the settable compositions may generally comprise water,pumice, hydrated lime, and a set retarder. Optionally, the settablecompositions may further comprise a set activator. Advantageously,embodiments of the settable compositions may be capable of remaining ina pumpable fluid state for an extended period of time—even afteractivation. For example, the settable compositions may remain in apumpable fluid state for about 1 day, about 3 days, about 5 days, about7 days, or longer. Moreover, embodiments of the settable composition maymaintain low gel strengths for extended periods of time, allowing theirdisplacement after remaining static in the wellbore for a period oftime. For example, the settable compositions may have a yield point lessthan 20 lbs./100 ft.² and gel-strength development less than about 25lbs./100 ft.² for about 1 day, about 3 days, about 5 days, about 7 days,or longer. In addition, the settable composition may have an initial setto 50 psi of about 1 day, about 2 days, about 5 days, or longer.Advantageously, the settable compositions may ultimately developreasonable compressive strengths after activation at relatively lowtemperatures. While the settable compositions may be suitable for anumber of subterranean operations, they may be particularly suitableoperations where it is desired to have an extended set after placementin the subterranean formation, such as settable spotting compositionsand puddle jobs. In embodiments, the settable compositions may be usedin subterranean formations having pressures up to about 15,000 psi orhigher.

The water used in embodiments of the settable compositions may be fromany source provided that it does not contain an excess of compounds thatmay undesirably affect other components in the settable compositions.For example, a settable composition may comprise fresh water or saltwater. Salt water generally may include one or more dissolved saltstherein and may be saturated or unsaturated as desired for a particularapplication. Seawater or brines may be suitable for use in embodiments.Further, the water may be present in an amount sufficient to form apumpable fluid. In certain embodiments, the water may be present in thesettable compositions in an amount in the range of from about 33% toabout 200% by weight of the pumice. In certain embodiments, the watermay be present in the settable compositions in an amount in the range offrom about 35% to about 70% by weight of the pumice. One of ordinaryskill in the art with the benefit of this disclosure will recognize theappropriate amount of water for a chosen application.

Embodiments of the settable compositions may comprise pumice. Generally,pumice is a volcanic rock that can exhibit cementitious properties inthat it may set and harden in the presence of hydrated lime and water.The pumice may also be ground. Generally, the pumice may have anyparticle size distribution as desired for a particular application. Incertain embodiments, the pumice may have a d50 particle sizedistribution in a range of from about 1 micron to about 200 microns. Thed50 values may be measured by particle size analyzers such as thosemanufactured by Malvern Instruments, Worcestershire, United Kingdom. Inspecific embodiments, the pumice may have a d50 particle sizedistribution in a range of from about 1 micron to about 200 microns,from about 5 microns to about 100 microns, or from about 10 microns toabout 25 microns. In one particular embodiment, the pumice may have ad50 particle size distribution of about 15 microns or less. An exampleof a suitable pumice is available from Hess Pumice Products, Inc.,Malad, Id., as DS-325 lightweight aggregate, having a d50 particle sizedistribution of about 15 microns or less. It should be appreciated thatparticle sizes too small may have mixability problems while particlesizes too large may not be effectively suspended in the compositions.One of ordinary skill in the art, with the benefit of this disclosure,should be able to select a particle size for the pumice suitable for achosen application.

Embodiments of the settable compositions may comprise hydrated lime. Asused herein, the term “hydrated lime” will be understood to mean calciumhydroxide. In some embodiments, the hydrated lime may be provided asquicklime (calcium oxide) which hydrates when mixed with water to formthe hydrated lime. The hydrated lime may be included in embodiments ofthe settable compositions, for example, to form a hydraulic compositionwith the pumice. For example, the hydrated lime may be included in apumice-to-hydrated-lime weight ratio of about 10:1 to about 1:1 or about3:1 to about 5:1. Where present, the hydrated lime may be included inthe settable compositions in an amount in the range of from about 10% toabout 100% by weight of the pumice, for example. In some embodiments,the hydrated lime may be present in an amount ranging between any ofand/or including any of about 10%, about 20%, about 40%, about 60%,about 80%, or about 100% by weight of the pumice. In some embodiments,the settable components present in the settable compositions may consistessentially of the pumice and the hydrated lime. For example, thesettable components may primarily comprise the pumice and the hydratedlime without any additional components (e.g., Portland cement, fly ash,slag cement) that hydraulically set in the presence of water. One ofordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate amount of the hydrated lime to include for achosen application.

Embodiments of the settable compositions may comprise a set retarder. Abroad variety of set retarders may be suitable for use in the settablecompositions. For example, the set retarder may comprise phosphonicacids, such as amino tris(methylene phosphonic acid), ethylenediaminetetra(methylene phosphonic acid), diethylenetriamine penta(methylenephosphonic acid), etc.; lignosulfonates, such as sodium lignosulfonate,calcium lignosulfonate, etc.; salts such as stannous sulfate, leadacetate, monobasic calcium phosphate, organic acids, such as citricacid, tartaric acid, etc.; cellulose derivatives such as hydroxyl ethylcellulose (HEC) and carboxymethyl hydroxyethyl cellulose (CMHEC);synthetic co- or ter-polymers comprising sulfonate and carboxylic acidgroups such as sulfonate-functionalized acrylamide-acrylic acidco-polymers; borate compounds such as alkali borates, sodium metaborate,sodium tetraborate, potassium pentaborate; derivatives thereof, ormixtures thereof. Examples of suitable set retarders include, amongothers, phosphonic acid derivatives. One example of a suitable setretarder is Micro Matrix® cement retarder, available from HalliburtonEnergy Services, Inc. Generally, the set retarder may be present in thesettable compositions in an amount sufficient to delay the setting for adesired time. In some embodiments, the set retarder may be present inthe settable compositions in an amount in the range of from about 0.01%to about 10% by weight of the pumice. In specific embodiments, the setretarder may be present in an amount ranging between any of and/orincluding any of about 0.01%, about 0.1%, about 1%, about 2%, about 4%,about 6%, about 8%, or about 10% by weight of the pumice. Additionallymore than one set retarder may be used for a given application, suchthat any embodiment of the settable compositions may comprise one ormore set retarders. One of ordinary skill in the art, with the benefitof this disclosure, will recognize the appropriate amount of setretarder to include for a chosen application.

As previously mentioned, embodiments of the settable compositions mayoptionally comprise a dispersant. Examples of suitable dispersantsinclude, without limitation, sulfonated-formaldehyde-based dispersants(e.g., sulfonated acetone formaldehyde condensate), examples of whichmay include Daxad 19 dispersant available from Geo Specialty Chemicals,Ambler, Pa. Other suitable dispersants may be polycarboxylated etherdispersants such as Liquiment® 5581F and Liquiment® 514L dispersantsavailable from BASF Corporation Houston, Tex.; or Ethacryl™ G dispersantavailable from Coatex, Genay, France. An additional example of asuitable commercially available dispersant is CFR™-3 dispersant,available from Halliburton Energy Services, Inc, Houston, Tex. TheLiquiment® 514L dispersant may comprise 36% by weight of thepolycarboxylated ether in water. While a variety of dispersants may beused in accordance with embodiments, polycarboxylated ether dispersantsmay be particularly suitable for use in some embodiments. Without beinglimited by theory, it is believed that polycarboxylated etherdispersants may synergistically interact with other components of thesettable compositions. For example, it is believed that thepolycarboxylated ether dispersants may react with certain set retarders(e.g., phosphonic acid derivatives) resulting in formation of a gel thatsuspends the pumice and hydrated lime in the settable compositions foran extended period of time.

In some embodiments, the dispersant may be included in the settablecompositions in an amount in the range of from about 0.01% to about 5%by weight of the pumice. In specific embodiments, the dispersant may bepresent in an amount ranging between any of and/or including any ofabout 0.01%, about 0.1%, about 0.5%, about 1%, about 2%, about 3%, about4%, or about 5% by weight of the pumice. One of ordinary skill in theart, with the benefit of this disclosure, will recognize the appropriateamount of the dispersant to include for a chosen application.

In some embodiments, a viscosifier may be included in the settablecompositions. The viscosifier may be included to optimize fluid rheologyand to stabilize the suspension. Without limitation, examples ofviscosifiers include swellable clays such as bentonite or biopolymerssuch as cellulose derivatives (e.g., hydroxyethyl cellulose,carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose). Anexample of a commercially available viscosifier is SA-1015™ availablefrom Halliburton Energy Services, Inc., Houston, Tex. The viscosifiermay be included in the settable compositions in an amount in the rangeof from about 0.01% to about 0.5% by weight of the pumice. In specificembodiments, the viscosifier may be present in an amount ranging betweenany of and/or including any of about 0.01%, about 0.05%, about 0.1%,about 0.2%, about 0.3%, about 0.4%, or about 0.5% by weight of thepumice. One of ordinary skill in the art, with the benefit of thisdisclosure, will recognize the appropriate amount of viscosifier toinclude for a chosen application.

Embodiments may include the addition of a set activator to the settablecompositions. The term “set activator” or “activator”, as used herein,refers to an additive that activates a set-delayed or retarded settablecomposition. A set activator may also accelerate the setting of theset-delayed or retarded settable composition. While embodiments describeinclusion of a set activator, the settable compositions may be activatedthermally. In embodiments where the settable compositions are activatedthermally, the settable compositions are activated by the heat of thesubterranean formation in which they are introduced. In embodimentswhere the settable compositions are activated by a set activator, theset activator may be added to the settable compositions prior to pumpingthe settable compositions into the subterranean formation. Whether toactivate the settable composition with a set activator or thermally withthe heat of the subterranean formation depends on a number of factors,including the downhole temperature and the desire to control slurryrheological and/or strength development properties. At low temperatures,thermal activation is not sufficient to drive hydration in thecompositions, and chemical activation is required. However, even at hightemperatures, when there is a desire to enhance development of earlystrength or late strength in the composition, which may, in someembodiments be a function of the slurry's rheology, or when there is aneed to suppress, for example, gas/fluid migration, a set activator mayallow for control over these properties whereas thermal activation mayjust initiate hydration and drive the reaction to completion.

Examples of suitable set activators include, but are not limited to:zeolites, amines such as triethanolamine, diethanolamine; silicates suchas sodium silicate; zinc formate; calcium acetate; Groups IA and IIAhydroxides such as sodium hydroxide, magnesium hydroxide, and calciumhydroxide; monovalent salts such as sodium chloride; divalent salts suchas calcium chloride; nanosilica (i.e., silica having a particle size ofless than or equal to about 100 nanometers); polyphosphates; andcombinations thereof. In some embodiments, a combination of thepolyphosphate and a monovalent salt may be used for activation. Themonovalent salt may be any salt that dissociates to form a monovalentcation, such as sodium and potassium salts. Specific examples ofsuitable monovalent salts include potassium sulfate, and sodium sulfate.A variety of different polyphosphates may be used in combination withthe monovalent salt for activation of the settable compositions,including polymeric metaphosphate salts, phosphate salts, andcombinations thereof. Specific examples of polymeric metaphosphate saltsthat may be used include sodium hexametaphosphate, sodiumtrimetaphosphate, sodium tetrametaphosphate, sodium pentametaphosphate,sodium heptametaphosphate, sodium octametaphosphate, and combinationsthereof. A specific example of a suitable set activator comprises acombination of sodium sulfate and sodium hexametaphosphate. Inparticular embodiments, the activator may be provided and added to thesettable compositions as a liquid additive, for example, a liquidadditive comprising a monovalent salt, a polyphosphate, and optionally adispersant. In embodiments, the set activator is typically added to thesettable compositions prior to introducing the settable compositionsinto the subterranean formation and/or wellbore; however, there may beinstances where it is necessary to add one or additional set activatorsto the settable compositions after they have been introduced to thesubterranean formation.

Some embodiments may include a set activator comprising a combination ofa monovalent salt and a polyphosphate. The monovalent salt and thepolyphosphate may be combined prior to their addition to the settablecompositions or they may be separately added to the settablecompositions. The monovalent salt may be any salt that dissociates toform a monovalent cation, such as sodium and potassium salts. Specificexamples of suitable monovalent salts include potassium sulfate andsodium sulfate. A variety of different polyphosphates may be used incombination with the monovalent salt for activation of the settablecompositions, including polymeric metaphosphate salts, phosphate salts,and combinations thereof, for example. Specific examples of polymericmetaphosphate salts that may be used include sodium hexametaphosphate,sodium trimetaphosphate, sodium tetrametaphosphate, sodiumpentametaphosphate, sodium heptametaphosphate, sodium octametaphosphate,and combinations thereof. A specific example of a suitable set activatorcomprises a combination of sodium sulfate and sodium hexametaphosphate.Interestingly, sodium hexametaphosphate is also known in the art to be astrong retarder of Portland cements. Because of the unique chemistry ofpolyphosphates, polyphosphates may be used as a set activator forembodiments of the settable compositions disclosed herein. The ratio ofthe monovalent salt to the polyphosphate may range, for example, fromabout 5:1 to about 1:25 or from about 1:1 to about 1:10. Embodiments ofthe set activator may comprise the monovalent salt and the polyphosphatesalt in a ratio (monovalent salt to polyphosphate) ranging between anyof and/or including any of about 5:1, 2:1, about 1:1, about 1:2, about1:5, about 1:10, about 1:20, or about 1:25.

In some embodiments, the combination of the monovalent salt and thepolyphosphate may be mixed with a dispersant and water to form a liquidadditive for activation of a settable composition. Examples of suitabledispersants include, without limitation, the previously describeddispersants, such as sulfonated-formaldehyde-based dispersants andpolycarboxylated ether dispersants. One example of a commercialdispersant is CFR3™ dispersant, available from Halliburton EnergyServices, Inc. One example of a suitable polycarboxylated etherdispersant is Liquiment® 514L or 5581F dispersants, available from BASFCorporation, Houston, Tex.

The liquid additive may function as a set activator. As discussed above,a set activator may also accelerate the setting of the settablecomposition. The use of a liquid additive to accelerate a settablecomposition is dependent upon the compositional makeup of the liquidadditive as well as the compositional makeup of the settablecompositions. With the benefit of this disclosure, one of ordinary skillin the art should be able to formulate a liquid additive to activateand/or accelerate settable compositions.

The set activator may be included in the settable compositions in anamount sufficient to induce the settable compositions to set into ahardened mass. In certain embodiments, the set activator may be includedin the settable compositions in an amount in the range of about 0.1% toabout 20% by weight of the pumice. In specific embodiments, the setactivator may be present in an amount ranging between any of and/orincluding any of about 0.1%, about 1%, about 5%, about 10%, about 15%,or about 20% by weight of the pumice. Additionally, more than one setactivator may be used, such that a combination of set activators may beprovided to the settable compositions. One of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriateamount of set activator to include for a chosen application.

Other additives suitable for use in subterranean operations also may beincluded in embodiments of the settable compositions. Examples of suchadditives include, but are not limited to: weighting agents, lightweightadditives, gas-generating additives, mechanical-property-enhancingadditives, lost-circulation materials, filtration-control additives,fluid-loss-control additives, defoaming agents, foaming agents,thixotropic additives, and combinations thereof. Examples of suitableweighting agents include, for example, materials having a specificgravity of 3 or greater, such as barite. In embodiments, one or more ofthese additives may be added to the settable compositions after storingbut prior to the placement of the settable compositions into asubterranean formation. A person having ordinary skill in the art, withthe benefit of this disclosure, should readily be able to determine thetype and amount of additive useful for a particular application anddesired result.

Those of ordinary skill in the art will appreciate that embodiments ofthe settable compositions generally should have a density suitable for aparticular application. By way of example, the settable compositions mayhave a density in the range of from about 4 pounds per gallon (“lb/gal”)to about 20 lb/gal. In certain embodiments, the settable compositionsmay have a density in the range of from about 8 lb/gal to about 17lb/gal. Embodiments of the settable compositions may be foamed orunfoamed or may comprise other means to reduce their densities, such ashollow microspheres, low-density elastic beads, or otherdensity-reducing additives known in the art. In embodiments, the densitymay be reduced after storing the composition, but prior to placement ina subterranean formation. Those of ordinary skill in the art, with thebenefit of this disclosure, will recognize the appropriate density for aparticular application.

The settable composition may be characterized by remaining in a pumpablefluid state for an extended period of time. When used in subterraneanoperations, the settable compositions may remain in a pumpable fluidstate at downhole conditions (even after activation) for a period oftime from about 1 day to about 7 days or longer. In some embodiments,the settable compositions may remain in a pumpable fluid state for about1 day, about 2 days, about 3 days, etc. The settable compositions may beactivated thermally or with a set activator. In embodiments where thesettable compositions are activated thermally, the settable compositionsare activated by the heat of the subterranean formation in which theyare introduced. In embodiments where the settable compositions areactivated by a set activator, the set activator may be added to thesettable compositions prior to pumping the settable compositions intothe subterranean formation. The thickening time of the settablecompositions refers to the measure of time that a settable composition(e.g., a settable spotting composition) remains in pumpable fluid state.A settable composition is considered to be in a pumpable fluid statewhere the fluid has a consistency of less than 70 Bearden units ofconsistency (“Bc”), as measured on a pressurized consistometer inaccordance with the procedure for determining cement thickening timesset forth in API RP Practice 1 OB-2, Recommended Practice for TestingWell Cements, First Edition, July 2005. The thickening times describedherein may be for any embodiment of the settable compositions usedwithin temperature ranges of about 140° F. to about 450° F. and forpressures ranging from the ambient pressure of the formation to greaterthan 15,000 psi.

When desired for use, embodiments of the settable compositions may beactivated (e.g., by combination with an activator) to set into ahardened mass. The term “set activator” or “activator”, as used herein,refers to an additive that activates a set-delayed or retarded settablecomposition. A set activator may also accelerate the setting of theset-delayed or retarded settable composition. By way of example,embodiments of the settable compositions may be activated to form ahardened mass in a time period in the range of from about 1 day to about7 days, or longer. For example, embodiments of the settable compositionsmay set to form a hardened mass in about 1 day, about 3 days, about 5days, about 7 days, or longer. The settable compositions may continue togain compressive strength over time periods exceeding 7 days.

In some embodiments, the settable compositions may set to have adesirable compressive strength after activation. However, the settablecompositions should not develop an initial compressive strength of 50psi for an extended period of time. Compressive strength is generallythe capacity of a material or structure to withstand axially directedpushing forces. The compressive strength may be measured at a specifiedtime after the settable composition has been activated and the resultantcomposition is maintained under specified temperature and pressureconditions. Compressive strength can be measured by either destructiveor non-destructive methods. The destructive method physically tests thestrength of treatment fluid samples at various points in time bycrushing the samples in a compression-testing machine. The compressivestrength is calculated from the failure load divided by thecross-sectional area resisting the load and is reported in units ofpound-force per square inch (psi). Non-destructive methods may employ aUCA™ ultrasonic cement analyzer, available from Fann Instrument Company,Houston, Tex. Compressive strength values may be determined inaccordance with API RP 10B-2, Recommended Practice for Testing WellCements, First Edition, July 2005.

The settable composition may be characterized by having an initial setto 50 psi of about 1 day or longer. For example, the settablecomposition may not develop 50 psi of compressive strength when allowedto set at downhole conditions for about 1 day or longer. By way ofexample, the settable composition may not develop 50 psi of compressivestrength for about 1 day, about 2 days, about 5 days, or even longer. Insome embodiments, the compressive strength values may be determinedusing destructive or non-destructive methods at a temperature rangingfrom 100° F. to 200° F.

In some embodiments, a settable composition may be provided thatcomprises water, pumice, hydrated lime, a set retarder, and optionally adispersant. The settable composition may be stored, for example, in avessel or other suitable container. The settable composition may bepermitted to remain in storage for a desired time period. For example,the settable composition may remain in storage for a time period ofabout 1 day or longer. As another example, the settable composition mayremain in storage for a time period of about 1 day, about 2 days, about5 days, about 7 days, about 10 days, about 20 days, about 30 days, about40 days, about 50 days, about 60 days, or longer. Thereafter, thesettable composition may be activated, for example, by the addition of aset activator, introduced into a subterranean formation, and thenallowed to set therein.

As will be appreciated by those of ordinary skill in the art,embodiments of the settable compositions may be used in a variety ofsubterranean operations where it is described for a settable compositionto remain pumpable for an extended period of time after placement. Forexample, the settable compositions may be used as settable spottingcompositions and in “puddle jobs.” In some embodiments, a settablecomposition may be provided that comprises water, pumice, hydrated lime,a set retarder, and optionally a set activator. The settablecompositions may be introduced into a subterranean formation and allowedto set therein. The properties of the settable composition when allowedto set in the formation may make it particularly suited for use as asettable spotting composition and/or in puddle jobs. For example, thesettable composition may remain in a pumpable fluid state for 1 day, 3days, 5 days, 7 days, or even longer. The settable composition may alsonot develop a compressive strength after introduction into thesubterranean formation for a period of 1 day, 3 days, 5 days, 7 days, oreven longer. Moreover, the settable composition may have a gel strengthof less than about 25 lbs./100 ft.² for about 1 day, 3 days, 5 days, 7days, or even longer and a yield point of less than about 20 lbs./100ft.² for about 1 day, 3 days, 5 days, 7 days, or even longer. As usedherein, introducing the settable compositions into a subterraneanformation includes introduction into any portion of the subterraneanformation, including, without limitation, into a wellbore drilled intothe subterranean formation, into a near wellbore region surrounding thewellbore, or into both. Embodiments may further include storage of thesettable compositions for extended time periods (e.g., about 1 day toabout 2 years) and also the activation of the settable compositions bythermal activation or by the addition of a set activator.

In embodiments, the settable composition may be used as a settablespotting composition in the displacement of a drilling fluid from awellbore. An example method may comprise introducing a settablecomposition into a wellbore so as to displace at least a portion of adrilling fluid from the wellbore. The settable composition may comprisewater, pumice, hydrated lime, a set retarder, and optionally a setactivator. The settable composition may be used to displace the drillingfluid from the wellbore before the drilling fluid has undesirablyincreased in gel strength. It may be desirable, in some embodiments, forthe settable composition to displace the drilling fluid from thoseportions of the wellbore containing fractures, vugs, and other permeableportions of the wellbore. After displacement of the drilling fluid,additional steps may include, but are not limited to, introducing a pipestring into the wellbore, and introducing a cement composition into thewellbore so as to displace at least a portion of the settable from thewellbore. Portions of the settable composition may remain in thewellbore, for example, in fractures or other permeable portions of thesubterranean formation. Those of ordinary skill in the art willappreciate that the cement composition also may displace any remainingdrilling fluid from the wellbore. After introduction therein, the cementcomposition should be allowed to set in the wellbore.

In embodiments, the settable composition may be used in puddle jobs. Anexample method may comprise introducing a settable composition into thewellbore and placing it in a puddle at the bottom of the wellbore or apuddle formed above a plug (e.g., in surface or near surfaceapplications). The settable composition may comprise water, pumice,hydrated lime, a set retarder, and optionally a set activator. Thesettable compositions may remain in a fluid state in a puddle at thebottom of the wellbore until a conduit is placed into the wellbore andpositioned. The settable compositions may then set in the annular spacebetween the conduit and the walls of a wellbore to form an annularsheath of a hardened mass. The hardened mass may form a barrier thatprevents the migration of fluids in the wellbore. The settablecomposition may also, for example, support the conduit in the wellbore.

An embodiment comprises a method for introducing a settable compositioninto a wellbore, the method comprising: providing a settable compositioncomprising pumice, hydrated lime, a set retarder, and water; introducingthe settable composition into a wellbore; and allowing the settablecomposition to remain static in the wellbore, wherein the settablecomposition remains in a pumpable fluid state for a period of about 1day or longer while static in the wellbore.

An additional embodiment comprises a method for introducing a settablecomposition into a wellbore, the method comprising: providing a settablecomposition comprising pumice, hydrated lime, a set retarder, and water;introducing the settable composition into the wellbore such that thesettable composition forms a puddle in the bottom of the wellbore; andallowing the settable composition to remain static in the wellbore,wherein the settable composition remains in a pumpable fluid state for aperiod of about 1 day or longer while static in the wellbore.

An additional embodiment comprises a settable composition system forsetting a casing comprising: wellbore casing disposed within a wellbore;a settable composition comprising: water, pumice, hydrated lime, and aset retarder; wherein the settable composition is capable of remainingin a fluid state of less than 70 Bc for a time period of about 5 days orlonger after the settable composition is introduced into the wellbore;mixing equipment capable of mixing the settable composition; and pumpingequipment capable of pumping the settable composition into the wellbore.

FIG. 1 illustrates surface equipment 5 that may be used in placement ofa settable composition in accordance with certain embodiments. It shouldbe noted that while FIG. 1 generally depicts a land-based operation;those skilled in the art will readily recognize that the principlesdescribed herein are equally applicable to subsea operations that employfloating or sea-based platforms and rigs, without departing from thescope of the disclosure. As illustrated by FIG. 1, the surface equipment5 may include a cementing unit 10, which may include one or more cementtrucks. The cementing unit 10 may include mixing equipment 15 andpumping equipment 20 as will be apparent to those of ordinary skill inthe art. The cementing unit 10 may pump a settable composition 25(depicted by the arrows) through a feed pipe 30 to a cementing head 35which conveys the settable composition 25 downhole.

An example of using settable composition 25 as a settable spottingcomposition will now be described with reference to FIGS. 2A-2D. FIG. 2Adepicts subterranean formation 40 penetrated by wellbore 45 withdrilling fluid 50 disposed therein. While the wellbore 45 is shownextending generally vertically into the subterranean formation 40, theprinciples described herein are also applicable to wellbores that extendat an angle through the subterranean formation 40, such as horizontaland slanted wellbores. The wellbore 45 may be drilled into thesubterranean formation 40 using any suitable drilling technique. Asillustrated, the drilling fluid 50 may be introduced into the wellbore45 through a drill string and bottom hole assembly (BHA) 55. On thewalls 60 of the wellbore 45 may be found pockets 65 which may have beencreated from washouts, fractures, crevices and/or otherwise naturallyoccurring features of the subterranean formation 40. A settablecomposition 25 may be run behind the drilling fluid 50, which occupiesthe lower portion of the drill string and BHA 55.

FIG. 2B depicts the subterranean formation 40 with the drill string andBHA 55 still placed downhole, and the settable composition 25 circulatedthrough the drill string and BHA 55 such that it exits the drill stringand BHA 55 and travels upward through the annulus 70 between the drillstring and BHA 55 and the walls 60 of wellbore 45, thus displacing thedrilling fluid 50. At least a portion of the displaced drilling fluid 50may exit the annulus 70 via a flow line 75 and be deposited, forexample, in one or more retention pits 80 (e.g., a mud pit), as shown inFIG. 1. While the settable composition 25 is exiting the drill stringand BHA 55 downhole, the drill string and BHA 55 may be circulated andreciprocated in a manner that improves removal of the drilling fluid 50trapped along the wellbore walls 60 and in the pockets 65.

As shown in FIG. 2C, after the drilling fluid 50 may be displaced by thesettable composition 25, the drill string and BHA 55 may be removed anda casing string 85 may be placed into the wellbore 45. A cementcomposition 90 may then be run behind the settable composition 25 in thecasing string 85, and, as depicted in FIG. 2D, circulated through thecasing string 85 such that it exits the bottom of the casing string 85and travels upward through the annulus 70 between the casing string 85and the walls 60 of the wellbore 45 to the predetermined top-of-cement(TOC) depth. In this case, any of the settable composition 25 that isnot displaced and remains on the walls 60 of the wellbore 45 and/or inthe pockets 65, will, in time, set into a hardened mass 95, thereforeprecluding the formation of undesirable channels and pathways throughwhich fluids may migrate.

An example of using a settable composition 25 in a “puddle job”operation will now be described with reference to FIGS. 3 and 4.Referring now to FIG. 3, the wellbore 45 is illustrated penetratingsubterranean formation 40. A casing string 85 may be run into thewellbore 45 to a depth placing the lower end of the casing string 85 tobe cemented above the critical interval through which a cement sheath isdesired. Mounted on the lower end of the casing string 85 may be a floatvalve 100 or any other type of plug (e.g., any sufficient sealing plugand not necessarily a valve). In embodiments, the float valve 100 may bea float valve of any type (e.g., a flapper float valve). The casingstring 85 may have centralizers 105 (e.g., as shown on FIG. 4) along itslength to keep the casing string 85 away from the walls 60 of thewellbore 45.

The settable composition 25 may be pumped and discharged into the lowerend of the wellbore 45. The settable composition 25 may be dischargedinto the lower end of the wellbore 45 via a drill string and BHA 55(e.g., as shown in FIGS. 2A-2B) which may be placed into the wellbore 45prior to positioning the casing string 85 into the wellbore 45.Alternatively, the settable composition 25 may be discharged into thelower end of the wellbore 45 via a drill string and BHA 55 (or othersuitable conduit) that is run through the casing string 85 such that thedrill string and BHA 55 exits through the lower end of the casing string85 via the float valve 100. The volume of the settable composition 25pumped into the wellbore 45 may depend on a number of factors, includingthe length of the interval needed to be set. For example, the settablecomposition 25 may remain in a pumpable fluid state (i.e., the settablecomposition has a consistency of less than 70 Bc) for a period of 1 day,3 days, 7 day, or longer. In practice, the settable composition 25should not set in the wellbore 45 until all operations requiring thesettable composition 25 to remain in a pumpable fluid state have beencompleted. It is therefore beneficial to have an accurate estimate ofthe duration of such operations prior to the formulation of the settablecomposition 25.

Turning now to FIG. 4, after the desired volume of the settablecomposition 25 has been discharged into the wellbore 45, the casingstring 85 may be lowered to the desired depth within the wellbore 45. Asillustrated, the casing string 85 is lowered into settable composition25 in the lower end of the wellbore 45. The float valve 100 shouldprevent entry of the settable composition 25 into the casing string 85.As the casing string 85 is lowered into wellbore 45, the settablecomposition 25 may be displaced from the middle of the wellbore 45 bythe casing string 85 with the annulus 70 surrounding the casing string85 containing the settable composition 25. The settable composition 25may be forced up the annulus 70 causing the settable composition 25, forexample, to displace any other fluids (e.g., drilling fluid 50 (notshown) and/or other fluids such as spacer fluids, displacement fluids,cleaning fluids, and the like) that may have remained in the wellbore45. The casing string 85 may then be suspended in the wellbore 45 untilthe settable composition 25 disposed in the annulus 70 has set.

The exemplary settable compositions disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed settable compositions. For example, thedisclosed settable compositions may directly or indirectly affect one ormore mixers, related mixing equipment, mud pits, storage facilities orunits, composition separators, heat exchangers, sensors, gauges, pumps,compressors, and the like used generate, store, monitor, regulate,and/or recondition the exemplary settable compositions. The disclosedsettable compositions may also directly or indirectly affect anytransport or delivery equipment used to convey the settable compositionsto a well site or downhole such as, for example, any transport vessels,conduits, pipelines, trucks, tubulars, and/or pipes used tocompositionally move the settable compositions from one location toanother, any pumps, compressors, or motors (e.g., topside or downhole)used to drive the settable compositions into motion, any valves orrelated joints used to regulate the pressure or flow rate of thesettable compositions, and any sensors (i.e., pressure and temperature),gauges, and/or combinations thereof, and the like. The disclosedsettable compositions may also directly or indirectly affect the variousdownhole equipment and tools that may come into contact with thesettable compositions such as, but not limited to, wellbore casing,wellbore liner, completion string, insert strings, drill string, coiledtubing, slickline, wireline, drill pipe, drill collars, mud motors,downhole motors and/or pumps, cement pumps, surface-mounted motorsand/or pumps, centralizers, turbolizers, scratchers, floats (e.g.,shoes, collars, valves, etc.), logging tools and related telemetryequipment, actuators (e.g., electromechanical devices, hydromechanicaldevices, etc.), sliding sleeves, production sleeves, plugs, screens,filters, flow control devices (e.g., inflow control devices, autonomousinflow control devices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like.

To facilitate a better understanding of the present embodiments, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the embodiments.

EXAMPLES Example 1

The following example describes a settable composition comprising thefollowing components:

TABLE 1 Compositional Makeup of Sample I Component Amount Unit* Water 60% bwoP Pumice 100 % bwoP Lime 20 % bwoP Weighting Agent 2 % bwoPRetarder 0.06 Gal/sk Co-Retarder 0.5 % bwoP Dispersant 0.6 % bwoPViscosifier 0.035 % bwoP Accelerator 2 % bwoP *% bwoP = by weight ofpumice; Gal/sk = gallons per 46 lb. sack of pumice

The weighting agent was Micromax® FF weight additive available fromHalliburton Energy Services, Inc., Houston, Tex. The cement retarder wasMicro Matrix® Cement Retarder available from Halliburton EnergyServices, Inc., Houston, Tex. The co-retarder was HR®-5 available fromHalliburton Energy Services, Inc., Houston, Tex. The dispersant wasLiquiment 5581F dispersant available from BASF, Florham Park, N.J. Theviscosifier was SA-1015™ suspending agent available from HalliburtonEnergy Services, Inc., Houston, Tex. The accelerator was an aqueoussolution of sodium hexametaphosphate (SHMP) and sodium sulfate in a 1:1ratio (6% activity). After preparation, the compressive strength of thesample was measured using a UCA maintained at 3,000 psi and 80° F. andwith a 10 minute ramp time in accordance with API RP Practice 10B-2,Recommended Practice for Testing Well Cements. The UCA test ran for 17days. At the conclusion of the UCA test, the destructive compressivestrength was measured by using a mechanical press to crush the samplesin accordance with the procedure set forth in API RP Practice 10B-2,Recommended Practice for Testing Well Cements. The rush strength wasmeasured as 473.7 psi. The results of the UCA compressive strengthtesting are presented in Table 2 below.

TABLE 2 UCA Compressive Strength Events Time (hh:mm) Time (dd:hh)  50psi 121:35  5:01 100 psi 173:44  7:06 250 psi 280:55 11:17 500 psi411:12 17:03

The composition did not gain compressive strength for approximately 60hours. Sample I reached initial set after 121 hours and achieved acompressive strength of 500 psi in over 411 hours. This indicates thatthe composition remained in a fluid state for at least 60 hours and didnot reach a reasonable compressive strength until after 121 hours. Thecomposition continued to gain compressive strength until the text wasterminated. In addition this sample was subjected to a static gelstrength analysis in accordance with the procedure set forth in APIRP-10b-6/ISO10426-6, Recommended Practice on Determining the Static GelStrength of Cement Formulations at 80° F., 3000 psi, which are the sameparameters as the UCA analysis. The sample exhibited zero gel time ofgreater than 13 days.

Example 2

In order to optimize the composition at higher temperatures, SamplesII-VI were prepared and subjected to thickening time (pump time) testson a high-pressure high-temperature consistometer. The compositionalmakeup of Samples II-VI are presented in Table 3 below.

TABLE 3 Compositional Makeup of Samples II-VI Sample II Sample IIISample IV Sample V Sample VI Component Unit* Amount Amount Amount AmountAmount Water % bwoP 60 60 60 60 60 Pumice % bwoP 100 100 100 100 100Lime % bwoP 20 20 20 20 20 Weighting Agent % bwoP 2 2 2 2 2 RetarderGal/sk 0.06 0.06 0.06 0.06 0.06 Co-Retarder % bwoP 0.5 0.5 0.5 0.5 0.5Dispersant % bwoP 0.6 0.6 0.6 0.6 0.6 Viscosifier % bwoP 0.035 0.0350.035 0.035 0.035 Accelerator % bwoP 10 5 2.5 1 0.5 *% bwoP = by weightof pumice; Gal/sk = gallons per 46 lb. sack of pumice

The weighting agent was Micromax® FF weight additive available fromHalliburton Energy Services, Inc., Houston, Tex. The cement retarder wasMicro Matrix® Cement Retarder available from Halliburton EnergyServices, Inc., Houston, Tex. The co-retarder was HR®-5 available fromHalliburton Energy Services, Inc., Houston, Tex. The dispersant wasLiquiment 5581F dispersant available from BASF, Florham Park, N.J. Theviscosifier was SA-1015™ suspending agent available from HalliburtonEnergy Services, Inc., Houston, Tex. The accelerator was an CaCl₂.

The thickening time, heat of hydration, and compressive strength weredetermined in accordance with API RP Practice 10B-2, RecommendedPractice for Testing Well Cements. After preparation, the thickeningtime was measured using a high-pressure high-temperature consistometerin accordance with API RP Practice 10B-2, Recommended Practice forTesting Well Cements with the experimental conditions set to 3,000 psiand 140° F., and having a ramp tome of 28 minutes. The heat ofhydration, or the time at which the heat of hydration occurs, wasdetermined through inspection of the thickening time test chart. Theheat of hydration is identified by an event which causes the sampletemperature to overtake the wall temperature which is the heat suppliedby the test equipment. The samples were poured into 2 inch by 4 inchbrass cylinders and cured in a water batch at 140° F. at atmosphericpressure. Then the destructive compressive strength was measured byusing a mechanical press to crush the samples in accordance with theprocedure set forth in API RP Practice 10B-2, Recommended Practice forTesting Well Cements. The results of these tests are set forth in Table4 below.

TABLE 4 Thickening Time Results Accelerator 70 BC Heat of 7 Day %Thickening Time Hydration Compressive Sample bwoP (hours) (hours)Strength (hours) II 10.0 12 18 1943 III 5.0 16 19 3073 IV 2.5 23 28 3812V 1.0 38 43 DNS* VI 0.5 50 66 DNS* *DNS = Did not set.

The results indicate that control over the pump time may be achieved byregulating the amount of accelerator formulated with the slurry.Additionally, it was discovered that the heat of hydration pointfollowed a similar trend as the pump time with respect to theaccelerator concentration such that the heat of hydration may serve asan indicator that the settable composition was undergoing hydration toset.

Example 3

Sample VII was prepared to build off the favorable results of Sample IV.Sample VII was prepared using additional retarder and dispersant. Thecompositional makeup of Sample VII is presented in Table 5 below.

TABLE 5 Compositional Makeup of Sample VII Component Amount Unit* Water60 % bwoP Pumice 100 % bwoP Lime 20 % bwoP Weighting Agent 2 % bwoPRetarder 0.093 Gal/sk Co-Retarder 0.5 % bwoP Dispersant 1.35 % bwoPViscosifier 0.035 % bwoP Accelerator 2 % bwoP *% bwoP = by weight ofpumice; Gal/sk = gallons per 46 lb. sack of pumice

The weighting agent was Micromax® FF weight additive available fromHalliburton Energy Services, Inc. Houston, Tex. The cement retarder wasMicro Matrix® Cement Retarder available from Halliburton EnergyServices, Inc., Houston, Tex. The co-retarder was HR®-5 available fromHalliburton Energy Services, Inc., Houston, Tex. The dispersant wasLiquiment 5581F dispersant available from BASF, Florham Park, N.J. Theviscosifier was SA-1015™ suspending agent available from HalliburtonEnergy Services, Inc., Houston, Tex. The accelerator was CaCl₂.

The thickening time, heat of hydration, and compressive strength weredetermined in accordance with API RP Practice 10B-2, RecommendedPractice for Testing Well Cements. The thickening time test wasconducted at 140° F. and 3000 psi. The samples were poured into 2 inchby 4 inch brass cylinders and cured in a water batch at 140° F. atatmospheric pressure for 7 days. Additionally, the samples were pouredinto 1 inch by 2 inch brass cylinders and cured in a water batch at 140°F. at 3000 psi for 7 days. After curing, the destructive compressivestrength was measured by using a mechanical press to crush the samplesin accordance with the procedure set forth in API RP Practice 10B-2,Recommended Practice for Testing Well Cements. Then the destructivecompressive strength was measured by using a mechanical press to crushthe samples in accordance with the procedure set forth in API RPPractice 10B-2, Recommended Practice for Testing Well Cements. Theresults of this test are set forth in Table 6 below.

TABLE 6 Thickening Time Results 70 BC Heat of 7 Day Compressive 7 DayCompressive Thickening Hydration Strength (140° F., Strength Time(hours) (hours) atmospheric pressure) (140° F., 3000 psi) 46 64 497 2190

Example 4

Samples VIII-XVI were prepared to test the settable compositions underthe high-temperature, high-pressure conditions of 350° F. and 15,000 psiusing a high-temperature high-pressure consistometer. The compositionalmakeup of Samples VIII-XVI are presented in Table 7 below.

TABLE 7 Compositional Makeup of Samples II-VI Sample Sample SampleSample Sample Sample Sample Sample VIII IX Sample X XI XII XIII XIV XVXVI Component* Amount Amount Amount Amount Amount Amount Amount AmountAmount Water 60 60 60 60 60 60 60 60 60 Pumice 100 100 100 100 100 100100 100 100 Lime 20 20 20 20 20 20 20 20 20 Weighting 2 2 2 2 2 2 2 2 2Agent Retarder 0.06 0.09 0.12 0.18 0.24 0.30 0.48 0.72 1.2 Co-Retarder0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 Dispersant 0.6 0.6 0.6 0.6 0.6 0.60.6 0.6 0.6 Viscosifier 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.0350.035 *All units are % bwoP (by weight of pumice) except for theRetarder which is Gal/sk = gallons per 46 lb. sack of pumice

The weighting agent was Micromax® FF weight additive available fromHalliburton Energy Services, Inc., Houston, Tex. The cement retarder wasMicro Matrix® Cement Retarder available from Halliburton EnergyServices, Inc., Houston, Tex. The co-retarder was HR®-5 available fromHalliburton Energy Services, Inc., Houston, Tex. The dispersant wasLiquiment 5581F dispersant available from BASF, Florham Park, N.J. Theviscosifier was SA-1015™ suspending agent available from HalliburtonEnergy Services, Inc., Houston, Tex.

The thickening time and the heat of hydration were determined using ahigh-temperature high-pressure consistometer in accordance with API RPPractice 10B-2, Recommended Practice for Testing Well Cements. The testwas conducted at 350° F. and 15,000 psi with a 28 minute ramp time. Theheat of hydration was determined through inspection of the thickeningtime test chart. The results of this test are set forth in Table 8below.

TABLE 8 Thickening Time Results 70 BC Heat of Retarder Thickening TimeHydration Sample Gal/sk (hours) (hours) VIII 0.06 1 1.5 IX 0.09 2.5 2.75X 0.12 6 6.75 XI 0.18 12 12.75 XII 0.24 17.5 19 XIII 0.3 20.5 22.25 XIV0.48 25 38.5 XV 0.72 37.75 51.75 XVI 1.2 61 61

As indicated in Table 7, the retarder concentration was steadilyincreased from Sample VIII to XVI. The results indicate a linearrelationship between pump time and retarder concentration. With 1.2Gal/sk retarder, the pump time was delayed to be greater than 60 hourswith the heat of hydration also indicating setting at greater than 60hours. Therefore, even in high-temperature, high-pressure environments,the settable compositions still exhibit delayed-set properties.

Additionally, settable compositions with retarder concentrations of 0.12gal/sk or greater also exhibit “right-angle” set behavior such that theset profile rapidly increases towards 70 Bc. Effectively Samples X-XVIshowed right-angle sets, while Samples VIII and IX did not. Settablecompositions with retarder concentrations less than 0.12 gal/sk had setprofiles which showed a gradual increase towards 70 Bc, which isindicative of gelation. Therefore, some formulations of the settablecompositions may also mitigate gelation and provide a settablecomposition that remains fluid for an extended period of time up until aspecific point in which it undergoes an immediate set. FIG. 5A providesan example of “right-angle” set profile using Sample XVI as an example.FIG. 5B provides an example of gelation set profile using Sample VIII asan example.

It should be understood that the compositions and methods are describedin terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent embodiments may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, all combinations of each embodiment are contemplated andcovered by the disclosure. Furthermore, no limitations are intended tothe details of construction or design herein shown, other than asdescribed in the claims below. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. It is therefore evident that the particularillustrative embodiments disclosed above may be altered or modified andall such variations are considered within the scope and spirit of thepresent disclosure. If there is any conflict in the usages of a word orterm in this specification and one or more patent(s) or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

What is claimed is:
 1. A method for introducing a settable compositioninto a wellbore, the method comprising: providing a settable compositioncomprising pumice, hydrated lime, a set retarder, and water, wherein thepumice, hydrated lime, and set retarder form a suspension in the water;introducing the settable composition into a wellbore; and allowing thesettable composition to remain static in the wellbore, wherein thesettable composition remains in a pumpable fluid state for a period of 1day or longer while static in the wellbore; wherein the settablecomposition is activated thermally in the wellbore.
 2. The method ofclaim 1 wherein the introducing the settable composition into thewellbore displaces at least a portion of a drilling fluid from asubterranean formation.
 3. The method of claim 2 further comprising:introducing a cement composition into the wellbore so as to at leastpartially displace the settable composition from the subterraneanformation; wherein a portion of the settable composition remains in thewellbore; allowing the cement composition to set in the wellbore; andallowing the portion of the settable composition remaining in thewellbore to set.
 4. The method of claim 1, wherein the settablecomposition is introduced into the wellbore such that the settablecomposition forms a puddle in the bottom of the wellbore, and whereinthe method further comprises: placing a conduit into the puddle formedby the settable composition in the bottom of the wellbore; and allowingthe settable composition to set in an annulus surrounding the conduit.5. The method of claim 1 wherein the set retarder comprises at least oneretarder selected from the group consisting of a phosphonic acid, aphosphonic acid derivative, a lignosulfonate, a salt, an organic acid, acarboxymethylated hydroxyethylated cellulose, a synthetic co- orter-polymer comprising sulfonate and carboxylic acid groups, and aborate compound.
 6. The method of claim 5 wherein the settablecomposition comprises an additional set retarder that is distinct fromthe set retarder.
 7. The method of claim 1 wherein the settablecomposition further comprises a dispersant.
 8. The method of claim 7wherein the dispersant comprises at least one dispersant selected fromthe group consisting of a sulfonated-formaldehyde-based dispersant, apolycarboxylated ether dispersant, and any combination thereof.
 9. Themethod of claim 1 wherein the settable composition has a compressivestrength of less than about 50 psi and a yield point of less than about20 lbs./ft.² after remaining static in the wellbore for a period of 1day or longer.
 10. The method of claim 1 where the settable compositionfurther comprises at least one set activator selected from the groupconsisting of zeolites, amines, silicates, Groups IA and IIA hydroxides,monovalent salts, divalent salts, nanosilica, polyphosphates, and anycombinations thereof.
 11. The method of claim 1 wherein the settablecomposition remains in a fluid state of less than 70 Bc for a timeperiod of 5 days or longer while static in the wellbore.
 12. A methodfor introducing a settable composition into a wellbore, the methodcomprising: providing a settable composition comprising pumice, hydratedlime, a set retarder comprising a phosphonic acid derivative, apolycarboxylated ether dispersant, and water; introducing the settablecomposition into a wellbore; allowing the settable composition to remainstatic in the wellbore, wherein the settable composition remains in apumpable fluid state for a period of 1 day or longer while static in thewellbore; and allowing the settable composition to thermally activateand set in the wellbore.
 13. The method of claim 12 wherein the settablecomposition remains in a fluid state of less than 70 Bc for a timeperiod of 5 days or longer while static in the wellbore.
 14. The methodof claim 12 wherein the settable composition has a compressive strengthof less than about 50 psi and a yield point of less than about 20lbs./ft.² after remaining static in the wellbore for a period of 1 dayor longer.
 15. A method for introducing a settable composition into awellbore, the method comprising: providing a settable compositioncomprising pumice, hydrated lime, a set retarder, and water; wherein thepumice, hydrated lime, and set retarder form a suspension in the water;introducing the settable composition into the wellbore such that thesettable composition forms a puddle in the bottom of the wellbore;allowing the settable composition to remain static in the wellbore,wherein the settable composition remains in a pumpable fluid state for aperiod of 1 day or longer while static in the wellbore; and allowing thesettable composition to thermally activate and set in the wellbore. 16.The method of claim 15 further comprising placing a conduit into thepuddle formed by the settable composition in the bottom of the wellbore;and allowing at least a portion of the settable composition to set in anannulus surrounding the conduit.
 17. The method of claim 15 wherein theset retarder comprises at least one retarder selected from the groupconsisting of a phosphonic acid, a phosphonic acid derivative, alignosulfonate, a salt, an organic acid, a carboxymethylatedhydroxyethylated cellulose, a synthetic co- or ter-polymer comprisingsulfonate and carboxylic acid groups, and a borate compound.
 18. Themethod of claim 15 wherein the settable composition further comprises atleast one set activator selected from the group consisting of zeolites,amines, silicates, Groups IA and IIA hydroxides, monovalent salts,divalent salts, and nanosilica, polyphosphates.
 19. The method of claim15 wherein the settable composition remains in a fluid state of lessthan 70 Bc for a time period of 5 days or longer while static in thewellbore.
 20. The method of claim 15 wherein the settable compositionhas a compressive strength of less than about 50 psi and a yield pointof less than about 20 lbs./ft.² after remaining static in the wellborefor a period of 1 day or longer.